The present invention relates to methods and compositions for corrosion inhibition. More particularly, in one or more embodiments, the present invention relates to corrosion inhibitor intensifier compositions that may be useful, inter alia, for enhancing the inhibition of metal corrosion in acidic environments, for example, those encountered in subterranean operations such as hydrocarbon recovery, and associated methods of use. The corrosion inhibitor intensifiers of the present invention may be used effectively in sour conditions.
Acidic fluids may be present in a multitude of operations in the oil and chemical industries. In these operations, metal surfaces in piping, tubing, heat exchangers, and reactors may be exposed to acidic fluids. Acidic fluids are often used as a treating fluid in wells penetrating subterranean formations. Such acidic treatment fluids may be used in, for example, clean-up operations or stimulation operations for oil and gas wells. Acidic stimulation operations may use these treatment fluids in hydraulic fracturing and matrix acidizing treatments. As used herein, the term “treatment fluid” refers to any fluid that may be used in an application in conjunction with a desired function and/or for a desired purpose. The term “treatment” does not imply any particular action by the fluid or any component thereof.
Acidizing and fracturing treatments using aqueous acidic treatment fluids commonly are carried out in hydrocarbon-containing subterranean formations penetrated by a well bore to accomplish a number of purposes, one of which is to increase the permeability of the formation. The increase in formation permeability normally results in an increase in the recovery of hydrocarbons from the formation. In acidizing treatments, generally aqueous acidic treatment fluids are introduced into the subterranean formation under pressure so that the acidic solution flows into the pore spaces of the formation. The acidic treatment fluid reacts with acid-soluble materials contained in the formation, resulting in an increase in the size of the pore spaces and an increase in the permeability of the formation. In fracture-acidizing treatments, one or more fractures are produced or enhanced in the formation, and the acidic treatment fluid is introduced into the fracture to etch flow channels in the fracture face. The acid also enlarges the pore spaces in the fracture face and in the formation.
The rate at which acidizing fluids react with reactive materials in the subterranean formation is a function of various factors, including, but not limited to, acid concentration, temperature, fluid velocity, and the type of reactive material encountered. Whatever the rate of reaction of the acidizing fluid, the fluid can be introduced into a the formation only a certain, distance before it becomes spent. It is desirable to maintain the acidizing fluid in a reactive condition for as long a period of time as possible to maximize the permeability enhancement produced by the acidizing fluid.
A common, problem associated with using acidic treatment fluids in subterranean formations is the corrosion of the tubular goods in the well bore and the other equipment used to carry out the treatment. As used herein, the term “corrosion” refers to any reaction between a material and its environment that causes some deterioration of the material or its properties. Examples of common types of corrosion include, but are not limited to, the rusting of metal, the dissolution of a metal in an acidic solution, and patina development on the surface of a metal. The expense of repairing or replacing corrosion damaged equipment is high. The corrosion problem may be exacerbated by the elevated temperatures encountered in deeper formations. The increased corrosion rate of the ferrous and other metals making up the tubular goods and other equipment results in quantities of the acidic solution being neutralized before it enters the subterranean formation. The partial neutralization of the acid results in the production of quantities of metal ions which are highly undesirable in the subterranean formation. Acidic treatment fluids may include a variety of acids such as, for example, hydrochloric acid, formic acid, hydrofluoric acid, and the like. While acidic treatment fluids may be useful for a variety of downhole operations, acidic treatment fluids can be problematic in that they can cause corrosion to downhole production tubing, downhole tools, and other surfaces in a subterranean formation.
To combat potential corrosion problems, an assortment of corrosion inhibitors has been used to reduce or prevent corrosion to downhole metals and metal alloys with varying levels of success. As used herein, the term “inhibit” and its derivatives refer to lessening the tendency of a phenomenon to occur and/or the degree to which that phenomenon occurs. The term “inhibit” does not imply any particular degree or amount of inhibition. A difficulty encountered with the use, of some corrosion inhibitors is the limited temperature range over which they may function effectively. For instance, certain conventional antimony-based inhibitor formulations have been limited to temperatures above 270° F. and do not appear to function effectively below this temperature.
Corrosion inhibitor intensifiers have been used to extend the performance range of a selected acid corrosion inhibitor. As used herein, the term “corrosion inhibitor intensifier” refers to compounds that are capable of enhancing the performance of a selected acid corrosion inhibitor. Unfortunately, most intensifiers do not perform universally with all corrosion inhibitors and many have temperature, time, and environmental drawbacks. For instance, formic acid, which is sometimes used as a corrosion inhibitor intensifier, is limited by a temperature range in which it performs of about 250° F. up to about 325° F. in 15% HCl. Potassium iodide is another intensifier that is sometimes used. It also has temperature limitations of about 325° F. that limit its usefulness. Additionally, some intensifiers, such as antimony-based intensifiers, can be used in conjunction with 15% HCl, but not with stronger acids such as 28% HCl. Another intensifier, cuprous iodide, is effective up to about 350° F., but has limited solubility in acid solutions. Additionally, cuprous iodide contains copper, a banned substance in some areas due to environmental considerations. As the older shallow and less corrosive oil and gas wells deplete, higher strength and more corrosion resistant materials or better corrosion inhibitors and intensifiers are needed to allow for deeper drilling in more corrosive environments.
It is beneficial to use alloys of increasing corrosion resistance and strength in subterranean applications. These increasing demands arise, from factors including: deep wells that involve higher temperatures and pressures; enhanced recovery methods such as steam or carbon dioxide (CO2) injection; increased tube stresses especially offshore; and corrosive well constituents including: hydrogen sulfide (H2S), CO2 and chlorides. Materials selection is especially critical for sour conditions, which are, those having H2S present. Sour well environments are highly toxic and extremely corrosive to traditional carbon steel oil and gas alloys. In some sour environments, corrosion can be controlled by using inhibitors along with carbon steel tubulars. The inhibitors, however, involve continuing high cost and are often unreliable at high temperatures. Additionally, conventional inhibitors are generally not thought to be effective in sour conditions.